Substations in high and medium-voltage power networks include primary devices such as electrical cables, lines, bus bars, switches, power transformers and instrument transformers, which can be arranged in switch yards and/or bays. These primary devices are operated in an automated way via a substation automation (SA) system. The SA system includes secondary devices, so-called intelligent electronic devices (IED), which are responsible for protection, control and monitoring of the primary devices. The IEDs may be assigned to hierarchical levels, i.e. the station level, the bay level, and the process level, where the latter is separated from the bay level by a so-called process interface. The station level of the SA system includes an operator work station (OWS) with a human-machine interface (HMI) and a gateway to a network control center (NCC). IEDs on the bay level, which can also be termed bay units, are in turn connected to each other as well as to the IEDs on the station level via an inter-bay or station bus primarily serving the purpose of exchanging commands and status information.
IEDs on the process-level can include electronic sensors for voltage (VT), current (CT) and gas density measurements, contact probes for sensing switch and transformer tap changer positions, and/or intelligent actuators (I/O) for controlling switchgear like circuit breakers or disconnectors. Exemplary process-level IEDs such as non-conventional current or voltage transformers can include an analog-to-digital (AD) converter for sampling of analog signals. Process-level IEDs can be connected to the bay units via a process bus, which can be considered as the process interface replacing a hard-wired process interface. The latter connects current or voltage transformers in the switchyard to the bay level equipment via dedicated copper (Cu) wires, in which case the analog signals of the instrument transformers can be sampled by the bay units.
A communication standard for communication between the secondary devices of a substation has been introduced by the International Electrotechnical Committee (IEC) as part of the standard IEC 61850 entitled “communication networks and systems in substations.” For non-time critical messages, IEC 61850-8-1 specifies the manufacturing message specification (MMS, ISO/IEC 9506) protocol based on a reduced open systems interconnection (OSI) protocol stack with the transmission control protocol (TCP) and Internet rotocol (IP) in the transport and network layer, respectively, and Ethernet and/or RS-232C as physical media. For time-critical event-based messages, IEC 61850-8-1 specifies the generic object oriented substation events (GOOSE) directly on the Ethernet link layer of the communication stack. For very fast periodically changing signals at the process level such as measured analog voltages or currents IEC 61850-9-2 specifies the sampled value (SV) service, which, similar to GOOSE, builds directly on the Ethernet link layer. Hence, the standard defines a format to publish, as multicast messages on an industrial Ethernet, event-based messages and digitized measurement data from current or voltage sensors on the process level. SV and GOOSE messages are transmitted over a process bus, which may, for example, result in cost-effective medium or low voltage substations, extend to neighbouring bays, (i.e. beyond the bay to which the sensor is assigned). In the latter case, the process bus transmits, in addition to the process data, command and/or status related messages otherwise exchanged via a dedicated station bus. In the following, the distinction between process and station bus in SA systems is eliminated.
In communication systems technology, within Local Area Networks (LAN) constructed by connecting a plurality of computers or other intelligent devices together, a concept called “virtual LAN” (VLAN) employs functionality for arbitrarily and logically grouping terminals or nodes which are connected to switches of the network. Ethernet VLANs according to IEEE 802.1Q allow restricting access to the terminals connected to an Ethernet network within a VLAN as well as restricting the data flow of multicast Ethernet messages to predefined parts of the Ethernet network where receiver terminals are connected which belong to the same VLAN. Hence a VLAN is able to reduce unnecessary network traffic and ensure security.
In Ethernet switch-based networks, VLAN definitions are handled within the Ethernet switches. Therefore, the latter are configured or otherwise made aware of the relevant VLANs. Specifically, for each port of a switch, the switch knows if a particular incoming VLAN (multicast) message shall be forwarded to this port or not (i.e., if this port also belongs as output port to the VLAN of the incoming message).
In Ethernet switch-based networks, it is assumed that any single connected terminal belongs to one specific VLAN. This terminal can then only talk to other terminals belonging to the same VLAN. When configuring the switches, the ports to these communicating terminals are therefore called access ports, and these access ports are only allowed to belong to one VLAN, while the other ports internal to the communication system, which are called trunk ports, may belong to several VLANs. As soon as the VLAN IDs of the access ports are known, the switches can automatically determine the VLAN IDs to which the trunk ports must belong. A VLAN can then either be manually configured into the switches, or automatically configured by means of a central table relating, for each terminal, the terminal's MAC address to a VLAN ID. However, the latter mechanism is disadvantageous because the central table has to be modified when replacing a failed terminal by a new one with a different MAC address, or because the address server containing this relation fails. Therefore, and especially within process control systems, the VLAN configuration is typically manually configured.
SA systems based on IEC61850 are configured by a standardized configuration representation or formal system description called substation configuration description (SCD). An SCD file includes the logical data flow between the IEDs on a “per message” base, i.e. for every message source, a list of destination or receiver IEDs, the message size in terms of data set definitions, as well as the message sending rates for all periodic traffic like GOOSE, SV and Integrity reports. The SCD file likewise specifies the distribution of multicast messages into Virtual Local Area Networks (VLANs), in which a single IED may send different real time messages for different purposes within different VLANs of the SA communication system. Hence the above concept of access ports can not be applied; however the concept of edge ports, i.e. ports which have not to be considered at RSTP loop avoidance algorithm in physically meshed networks, is still valid (in this notation, an edge port connected to an end node or IED that is assigned to one single VLAN corresponds to an access port). This can complicate the configuration of VLANs on the switches.
Furthermore, the assumption of all IEDs spontaneously sending data within their VLAN is normally not applicable for SA real time applications containing pure message receivers for certain VLANs. In addition, the receivers of messages of a VLAN may not send messages within the same VLAN (they do not send any VLAN messages, or within another VLAN). Both these facts prohibit automatic VLAN detection by the switches based on received messages.
For large SA or process control systems with increased real time critical communication needs due to multicast communication traversing the entire system, the communication network load is of interest. This is e.g. the case for GOOSE and SV messages from IEC 61850. In addition, station level IEDs such as operator work station and gateway, may not be adapted to handle more than 200 to 1000 messages per second. Principles and methods of the present disclosure are not restricted to a use in substation automation, but are likewise applicable to other process control systems with a standardized configuration description. For example, IEC 61850 is also an accepted standard for Hydro power plants, Wind power systems, and Distributed Energy Resources (DER).